Subsea wellbore drilling system for reducing bottom hole pressure

ABSTRACT

The present invention provides drilling systems for drilling subsea wellbores. The drilling system includes a tubing that passes through a sea bottom wellhead and carries a drill bit. A drilling fluid system continuously supplies drilling fluid into the tubing, which discharges at the drill bit bottom and returns to the wellhead through an annulus between the tubing and the wellbore carrying the drill cuttings. A fluid return line extending from the wellhead equipment to the drilling vessel transports the returning fluid to the surface. In a riserless arrangement, the return fluid line is separate and spaced apart from the tubing. In a system using a riser, the return fluid line may be the riser or a separate line carried by the riser. The tubing may be coiled tubing with a drilling motor in the bottom hole assembly driving the drill bit. A suction pump coupled to the annulus is used to control the bottom hole pressure during drilling operations, making it possible to use heavier drilling muds and drill to greater depths than would be possible without the suction pump. An optional delivery system continuously injects a flowable material, whose fluid density is less than the density of the drilling fluid, into the returning fluid at one or more suitable locations the rate of such lighter material can be controlled to provide supplementary regulation of the pressure. Various pressure, temperature, flow rate and kick sensors included in the drilling system provide signals to a controller that controls the suction pump, the surface mud pump, a number of flow control devices, and the optional delivery system.

REFERENCE TO CORRESPONDING APPLICATIONS

[0001] This application claims benefit of U.S. Provisional ApplicationNo. 60/108,601, filed Nov. 16, 1998, U.S. Provisional Application No.60/101,541, filed Sep. 23, 1998, U.S. Provisional Application No.60/092,908, filed, Jul. 15, 1998 and U.S. Provisional Application No.60/095,188, filed Aug. 3, 1998.

BACKGROUND OF THE INVENTION

[0002] 1. Field of the Invention

[0003] This invention relates generally to oilfield wellbore systems forperforming wellbore operations and more particularly to subsea downholeoperations at an offshore location in which drilling fluid iscontinuously circulated through the wellbore and which utilizes a fluidreturn line that extends from subsea wellhead equipment to the surfacefor returning the wellbore fluid from the wellhead to the surface.Maintenance of the fluid pressure in the wellbore during drillingoperations at predetermined pressures is key to enhancing the drillingoperations.

[0004] 2. Background of the Art

[0005] Oilfield wellbores are drilled by rotating a drill bit conveyedinto the wellbore by a drill string. The drill string includes adrilling assembly (also referred to as the “bottom hole assembly” or“BHA”) that carries the drill bit. The BHA is conveyed into the wellboreby tubing. Continuous tubing such as coiled tubing or jointed tubing isutilized to convey the drilling assembly into the wellbore. The drillingassembly usually includes a drilling motor or a “mud motor” that rotatesthe drill bit. The drilling assembly also includes a variety of sensorsfor taking measurements of a variety of drilling, formation and BHAparameters. A suitable drilling fluid (commonly referred to as the“mud”) is supplied or pumped under pressure from the surface down thetubing. The drilling fluid drives the mud motor and discharges at thebottom of the drill bit. The drilling fluid returns uphole via theannulus between the drill string and the wellbore inside and carriespieces of formation (commonly referred to as the “cuttings”) cut orproduced by the drill bit in drilling the wellbore.

[0006] For drilling wellbores under water (referred to in the industryas “offshore” or “subsea” drilling) tubing is provided at the surfacework station (located on a vessel or platform). One or more tubinginjectors or rigs are used to move the tubing into and out of thewellbore. Injectors may be placed at the sea surface and/or on thewellhead equipment at the sea bottom. In riser-type drilling, a riser,which is formed by joining sections of casing or pipe, is deployedbetween the drilling vessel and the wellhead equipment and is utilizedto guide the tubing to the wellhead. The riser also serves as a conduitfor fluid returning from the wellhead to the sea surface. Alternatively,a return line, separate and spaced apart from the tubing, may be used toreturn the drilling fluid from the wellbore to the surface.

[0007] During drilling, the operators attempt to carefully control thefluid density at the surface so as to ensure an overburdened conditionin the wellbore. In other words, the operator maintains the hydrostaticpressure of the drilling fluid in the wellbore above the formation orpore pressure to avoid well blow-out. The density of the drilling fluidand the fluid flow rate control largely determine the effectiveness ofthe drilling fluid to carry the cuttings to the surface. For suchpurpose, one important downhole parameter controlled is the equivalentcirculating density (“ECD”) of the fluid at the wellbore bottom. The ECDat a given depth in the wellbore is a function of the density of thedrilling fluid being supplied and the density of the returning fluidwhich includes the cuttings at that depth.

[0008] When drilling at offshore locations where the water depth is asignificant fraction of the total depth of the wellbore, the absence ofa formation overburden causes a reduction in the difference between porefluid pressure in the formation and the pressure inside the wellbore dueto the drilling mud. In addition, the drilling mud must have a densitygreater than that of seawater so then if the wellhead is open toseawater, the well will not flow. The combination of these two factorscan prevent drilling to certain target depths when the full column ofmud is applied to the annulus. The situation is worsened when liquidcirculation losses are included, thereby increasing the solidsconcentration and creating an ECD of the return fluid even greater thanthe static mud weight.

[0009] In order to be able to drill a well of this type to a totalwellbore depth at a subsea location, the bottom hole ECD must bereduced. One approach to do so is to use a mud filled riser to form asubsea fluid circulation system utilizing the tubing, BHA, the annulusbetween the tubing and the wellbore and the mud filled riser, and theninject gas (or some other low density liquid) in the primary drillingfluid (typically in the annulus adjacent the BHA) to reduce the densityof fluid downstream (i.e., in the remainder of the fluid circulationsystem). This so-called “dual density” approach is often referred to asdrilling with compressible fluids.

[0010] Another method for changing the density gradient in a deepwaterreturn fluid path has been proposed, but not used in practicalapplication. This approach proposes to use a tank, such as an elasticbag, at the sea floor for receiving return fluid from the wellboreannulus and holding it at the hydrostatic pressure of the water at thesea floor. Independent of the flow in the annulus, a separate returnline connected to the sea floor storage tank and a subsea lifting pumpdelivers the return fluid to the surface. Although this technique (whichis referred to as “dual gradient” drilling) would use a single fluid, itwould also require a discontinuity in the hydraulic gradient linebetween the sea floor storage tank and the subsea lifting pump. Thisrequires close monitoring and control of the pressure at the subseastorage tank, subsea hydrostatic water pressure, subsea lifting pumpoperation and the surface pump delivering drilling fluids under pressureinto the tubing for flow downhole. The level of complexity of therequired subsea instrumentation and controls as well as the difficultyof deployment of the system has delayed (if not altogether prevented)the practical application of the “dual gradient” system.

SUMMARY OF THE INVENTION

[0011] The present invention provides wellbore systems for performingsubsea downhole wellbore operations, such as subsea drilling asdescribed more fully hereinafter, as well as other wellbore operations,such as wellbore reentry, intervention and recompletion. Such drillingsystem includes tubing at the sea level. A rig at the sea level movesthe tubing from the reel into and out of the wellbore. A bottom holeassembly, carrying the drill bit, is attached to the bottom end of thetubing. A wellhead assembly at the sea bottom receives the bottom holeassembly and the tubing. A drilling fluid system continuously suppliesdrilling fluid into the tubing, which discharges at the drill bit andreturns to the wellhead equipment carrying the drill cuttings. A pump atthe surface is used to pump the drilling fluid downhole. A fluid returnline extending from the wellhead equipment to the surface work stationtransports the returning fluid to the surface.

[0012] In the preferred embodiment of the invention, an adjustable pumpis provided coupled to the annulus of the well. The lift provided by theadjustable pump effectively lowers the bottom hole pressure. In analternative embodiment of the present invention, a flowable material,whose fluid density is less than the density of the returning fluid, isinjected into a return line separate and spaced from the tubing at oneor more suitable locations in the return line or wellhead. The rate ofinjection of such lighter material can be controlled to provideadditional regulation of the pressure the return line and to maintainthe pressure in the wellbore at predetermined values throughout thetripping and drilling operations.

[0013] Some embodiments of the drilling system of this invention arefree of subsea risers that usually extend from the wellhead equipment tothe surface and carry the returning drilling fluid to the surface. Fluidflow control devices may also be provided in the return line and in thetubing. Sensors make measurements of a variety of parameters related toconditions of the return fluid in the wellbore. These measurements areused by a control system, preferably at the surface, to controlthe-surface and Adjustable pumps, the injection of low density fluid ata controlled flow rate and flow restriction devices included in thedrilling system. In other embodiments of the invention, subsea risersare used as guide tubes for the tubing and a surge tank or stand pipe incommunication with the return fluid in the flow of the fluid to thesurface.

[0014] These features (in some instances acting individually and otherinstances acting in combination thereof) regulate the fluid pressure inthe borehole at predetermined values during subsea downhole operationsin the wellbore by operating the adjustable pump system to overcome atleast a portion of the hydrostatic pressure and friction loss pressureof the return fluid. Thus, these features enable the downhole pressureto be varied through a significantly wider range of pressures thanpreviously possible, to be adjusted far faster and more responsivelythan previously possible and to be adjusted for a wide range ofapplications (i.e., with or without risers and with coiled or jointedtubing). In addition, these features enable the bottom hole pressure tobe regulated throughout the entire range of downhole subsea operations,including drilling, tripping, reentry, recompletion, logging and otherintervention operations, which has not been possible earlier. Moreover,the subsea equipment necessary to effect these operational benefits canbe readily deployed and operationally controlled from the surface. Theseadvantages thus result in faster and more effective subsea downholeoperations and more production from the reservoir, such as settingcasing in the wellbore.

[0015] Examples of the more important features of the invention havebeen summarized (albeit rather broadly) in order that the detaileddescription thereof that follows may be better understood and in orderthat the contributions they represent to the art may be appreciated.There are, of course, additional features of the invention that will bedescribed hereinafter and which will form the subject of the claimsappended hereto.

BRIEF DESCRIPTION OF THE DRAWINGS

[0016] For detailed understanding of the present invention, referenceshould be made to the following detailed description of the preferredembodiment, taken in conjunction with the accompanying drawings, inwhich like elements have been given like numerals:

[0017]FIG. 1 is a schematic elevational view of a wellbore system forsubsea downhole wellbore operations wherein fluid, such as a drillingfluid, is continuously circulated through the wellbore during drillingof the wellbore and wherein a controlled lift device is used to regulatethe bottom hole ECD through a wide range of pressures.

[0018]FIG. 2 is a schematic illustration of the fluid flow path for thedrilling system of FIG. 1 and the placement of certain devices andsensors in the fluid path for use in controlling the pressure of thefluid in the wellbore at predetermined values and for controlling theflow of the returning fluid to the surface.

[0019]FIG. 3 is a schematic similar to FIG. 2 showing another embodimentof this invention utilizing a tubing guide tube or stand pipe as a surgetank.

[0020] FIGS. 4A-4C illustrate the pressure profiles obtained by usingthe present invention compared to prior art pressure profiles.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

[0021]FIG. 1 shows a schematic elevational view of a drilling system 100for drilling subsea or under water wellbores 90. The drilling system 100includes a drilling platform, which may be a drill ship 101 or anothersuitable surface work station such as a floating platform or asemi-submersible. Various types of work stations are used in theindustry for drilling or performing other wellbore operations in subseawells. A drilling ship or a floating rig is usually preferred fordrilling deep water wellbores, such as wellbores drilled under severalthousand feet of water. To drill a wellbore 90 under water, wellheadequipment 125 is deployed above the wellbore 90 at the sea bed or bottom121. The wellhead equipment 125 includes a blow-out-preventer stack 126.A lubricator (not shown) with its associated flow control valves may beprovided over the blow-out-preventer 126. The flow control valvesassociated with the lubricator control the discharge of the returningdrilling fluid from the lubricator.

[0022] The subsea wellbore 90 is drilled by a drill bit carried by adrill string, which includes a drilling assembly or a bottom holeassembly (“BHA”) 130 at the bottom of a suitable tubing, such ascontinuous tubing 142. It is contemplated that jointed tubing may alsobe used in the invention. The continuous tubing 142 is spooled on a reel180, placed at the vessel 101. To drill the wellbore 90, the BHA 130 isconveyed from the vessel 101 to the wellhead equipment 125 and theninserted into the wellbore 90. The tubing 142 is moved from the reel 180to the wellhead equipment 125 and then moved into and out of thewellbore 90 by a suitable tubing injection system. FIG. 1 shows oneembodiment of a tubing injection system comprising a first or supplyinjector 182 for feeding a span or loop 144 of tubing to the second ormain tubing injector 190. A third or subsea injector (not shown) may beused at the wellhead to facilitate injection of the tubing 142 in thewellbore 90.

[0023] Installation procedures to move the bottom hole assembly 130 intothe wellbore 90 is described in U.S. Pat. No. 5,738,173, commonlyassigned with this application.

[0024] The primary purpose of the injector 182 is to move the tubing 142to the injector 190 and to provide desired tension to the tubing 142. Ifa subsea injector is used, then the primary purpose of the surfaceinjector 190 is to move the tubing 142 between the reel 180 and thesubsea injector. If no subsea injector is used, then the injector 190 isused to serve the purpose of the subsea injector. For the purpose ofthis invention any suitable tubing injection system may be utilized.

[0025] To drill the wellbore 90, a drilling fluid 20 from a surface mudsystem 22 (see FIG. 2, for details) is pumped under pressure down thetubing 142. The fluid 20 operates a mud motor in the BHA 130 which inturn rotates the drill bit. The drill bit disintegrates the formation(rock) into cuttings. The drilling fluid 20 leaving the drill bittravels uphole through the annulus between the drill string and thewellbore carrying the drill cuttings. A return line 132 coupled to asuitable location at the wellhead 125 carries the fluid returning fromthe wellbore 90 to the sea level. As shown in FIG. 2, the returningfluid discharges into a separator or shaker 24 which separates thecuttings and other solids from the returning fluid and discharges theclean fluid into the suction or mud pit 26. In the prior art methods,the tubing 142 passes through a mud filled riser disposed between thevessel and the wellhead, with the wellbore fluid returning to thesurface via the riser. Thus, in the prior art system, the riserconstituted an active part of the fluid circulation system. In oneaspect of the present invention, a separate return line 132 is providedto primarily return the drilling fluid to the surface. The return line132, which is usually substantially smaller than the riser, can be madefrom any suitable material and may be flexible. A separate return lineis substantially less expensive and lighter than commonly used risers,which are large diameter jointed pipes used especially for deep waterapplications and impose a substantial suspended weight on the surfacework station. FIG. 2 shows the fluid flow path during the drilling of awellbore 90 according to the present invention.

[0026] In prior art pumping systems, pressure is applied to thecirculating fluid at the surface by means of a positive displacementpump 28. The bottom hole pressure (BHP) can be controlled while pumpingby combining this surface pump with an adjustable pump system 30 on thereturn path and by controlling the relative work between the two pumps.The splitting of the work also means that the size of the surface pump28 can be reduced. Specifically, the circulating can be reduced by asmuch as 1000 to 3000 psi. The limit on how much the pressure can belowered is determined by the vapor pressure of the return fluid. Thesuction inlet vapor pressure of the adjustable pumps 28 and 30 mustremain above the vapor pressure of the fluid being pumped. In apreferred embodiment of the invention, the net suction head is two tothree times the vapor pressure of the fluid to prevent local cavitationin the fluid.

[0027] More specifically, the surface pump 28 is used to control theflow rate and the adjustable pump 30 is used to control the bottom holepressure, which in turn will affect the hydrostatic pressure. Aninterlinked pressure monitoring and control circuit 40 is used to ensurethat the bottom hole pressure is maintained at the correct level. Thispressure monitoring and control network is, in turn, used to provide thenecessary information and to provide real time control of the adjustablepump 30.

[0028] Referring now to FIG. 2, the mud pit 26 at the surface is asource of drilling fluid that is pumped into the drill pipe 142 bysurface pump 28. After passing through the tubing 142, the mud is usedto operate the BHA 130 and returns via the annulus 146 to the wellhead125. Together the tubing 142, annulus 146 and the return line 132constitutes a subsea fluid circulation system.

[0029] The adjustable pump 30 in the return line provides the ability tocontrol the bottom hole pressure during drilling of the wellbore, whichis discussed below in reference to FIGS. 4A-4C. A sensor P1 measures thepressure in the drill line above an adjustable choke 150 in the tubing142.

[0030] A sensor P2 is provided to measure the bottom hole fluid pressureand a sensor P3 is provided to measure parameters indicative of thepressure or flow rate of the fluid in the annulus 146. Above thewellhead, a sensor P4 is provided to measure parameters similar to thoseof P3 for the fluid in the return line and a controlled valve 152 isprovided to hold fluid in the return line 132. In operation, the controlunit 40 and the sensor P1 operate to gather data relating to the tubingpressure to ensure that the surface pump 28 is operating against apositive pressure, such as at sensor P5, to prevent cavitation, with thecontrol unit 40 adjusting the choke 150 to increase the flow resistanceit offers and/or to stop operation of the surface pump 28 as may berequired. Similarly, the control system 40 together with sensors P2, P3and/or P4 gather data, relative to the desired bottom hole pressure andthe pressure and/or flow rate of the fluid in the return line 132 andthe annulus 146, necessary to achieve a predetermined downhole pressure.More particularly, the control system acting at least in part inresponse to the data from sensors P2, P3 and/or P4 controls theoperation of the adjustable pump 30 to provide the predetermineddownhole pressure operations, such as drilling, tripping, reentry,intervention and recompletion. In addition, the control system 40controls the operation of the fluid circulation system to preventundesired flow of fluid within the system when the adjustable pump isnot in operation. More particularly, when operation of the pumps 28, 30is stopped a pressure differential may be resident in the fluidcirculation system tending to cause fluid to flow from one part of thesystem to another. To prevent this undesired situation, the controlsystem operates to close choke 150 in the tubing, valve 152 in thereturn line or both devices.

[0031] The adjustable pump 30 preferably comprises a centrifugal pump.Such pumps have performance curves that provide more or less a constantflow rate through the adjustable pump system 30 while allowing changesin the pressure increase of fluid in the pump. This can be done bychanging the speed of operation of the pump 30, such as via a variablespeed drive motor controlled by the control system 40. The pump systemmay also comprise a positive displacement pump provided with a fluidby-pass line for maintaining a constant flow rate through the pumpsystem, but with control over the pressure increase at the pump. In theFIG. 2 embodiment of the invention, the adjustable pump system 30 may beused with the separate return line 132, as shown, or may be used inconjunction with the conventional mud-filled riser (not shown).

[0032]FIG. 3 shows an alternative lifting system intended for use with areturn line 132, such as that shown, that is separate and spaced apartfrom the tubing 142. In this embodiment, a flowable material of lowerdensity than the return fluid from a suitable source 60 thereof at thesurface is injected in the return fluid by a suitable injector 62 in thesubsea circulation system to lift the return fluid and reduce theeffective ECD and bottom hole pressure. The flowable material may be asuitable gas such as nitrogen or a suitable liquid such as water. Likethe adjustable pump system 30, the injector 62 is preferably used inconjunction with sensors P1, P2, P3, P4 and/or P5 and controlled by thecontrol system 40 to control the bottom hole pressure. In addition, theinjection system may constitute the sole lift system in the fluidcirculation system, or is used in conjunction with the adjustable pumpsystem 30 to overcome at least a portion of the hydrostatic pressure andfriction loss pressure of the return fluid.

[0033]FIG. 3 also shows a tube 70 extending from the surface workstation 101 down to the wellhead 125 that may be employed in the fluidcirculation system of this invention. However, in contrast to theconventional mud-filled riser, the tube 70 rather serves as a guide tubefor the tubing 142 and a surge tank selectively used for a limited andunique purpose as part of the fluid circulation system. Moreparticularly the tube 70 serves to protect the tubing 142 extendingthrough the turbulent subsea zone down to the wellhead. In addition, thetube has a remotely operated stripper valve 78 that when closed blocksfluid flow between the return line 132 and the annulus 146 and whenopened provides fluid flow communication into the interior of the tubingfrom the return line and the annulus. Thus, with the stripper valveclosed, the fluid circulation system operates in the manner describedabove for the FIGS. 2 and 3 embodiments of this invention, in whichthere is a direct correspondence of the flow rate of fluid delivered tothe system by the surface pump 28 and fluid flowing past the adjustablepump system 30 or injector 62. However, in contrast to this closedsystem, when the stripper valve 78 is opened, an open system is createdoffering a unique operating flexibility for a range of pressures in thefluid circulation system at the wellhead 125 at or above sea floorhydrostatic pressure. More particularly, with the stripper valve open,the tube 70 operates as a surge tank filled in major part by sea water76 and is also available to receive return flow of mud if the pressurein the fluid circulation system at the wellhead 125 is at a pressureequal to or greater than sea floor hydrostatic pressure. At suchpressures, the mud/water 72 rises with the height of the column 74adjusting in response to the pressure changes in the fluid circulationsystem. This change in the mud column also permits the flow rate of thefluid established by the adjustable pump system 30 or injector 62 todiffer from that of the surface pump 28. This surge capacity providestime for the system to adjust to pump rate mismatches that may occur inthe system and to do so in a self-adjusting manner. Further criticalpressure downhole measurements of the fluid circulation system may betaken at the surface via the guide tube 70. More particularly, as theheight of the mud column 74 changes, the column of water 76 isdischarged (or refilled) at the surface work station 101. Measuring thissurface flow of water such as at a suitable flowmeter 80 provides aconvenient measure of the pressure of the return fluid at the wellhead125.

[0034] The use of the adjustable pump 30 (or controlled injector 62) isdiscussed now with reference to FIGS. 4A-4C. FIG. 4A shows a plot ofstatic pressure (abscissa) against subsea and then wellbore depth(ordinate) at a well. The pore pressure of the formation in a normallypressured rock is given by the line 303. Typically drilling mud that hasa higher density than water is used in the borehole to prevent anunderbalanced condition leading to blow-out of formation fluid. Thepressure inside the borehole is represented by 305. However, when theborehole pressure 305 exceeds the fracture pressure FP of the formation,which occurs at the depth 307, further drilling below depth 307 usingthe mud weight corresponding to 305 is no longer possible.

[0035] With conventional fluid circulation systems, either the densityof the drilling mud must be decreased and the entire quantity of heavydrilling mud displaced from the circulation system, which is a timeconsuming and costly process, or a steel casing must be set in thebottom of the wellbore 307, which is also time consuming and costly ifrequired more often than called for in the wellbore plan. Moreover,early setting of casing causes the well to telescope down to smallerdiameters (and hence to lower production capacity) than otherwisedesirable.

[0036]FIG. 4B shows dynamic pressure conditions when mud is flowing inthe borehole. Due to frictional losses due to flow in the drillsting,shown at line P_(D), and in the annulus, shown at line P_(A), thepressure at a depth 307 is given by a value 328, i.e., defining aneffective circulating density (ECD) by the pressure gradient line 309.The pressure at the bottom of the hole 328 exceeds the static fluidhydrostatic pressure 305 by an additional amount over and above thefracture pressure FP shown in FIG. 4A. This excess pressure P_(A) isessentially equal to the frictional loss in the annulus for the returnflow. Therefore, even with drilling fluid of lower density than that forgradient line 305 circulating in the circulation system, a well cannotbe drilled to the depth indicated by 307. With enough pressure drop dueto fluid friction loss, drilling beyond the depth 307 may not bepossible even using only water.

[0037] Prior art methods using the dual density approach seek to reducethe effective borehole fluid pressure gradient by reducing the densityof the fluid in the return line. It also illustrates one of the problemswith relying solely upon density manipulation for control of bottom holepressure. Referring to FIG. 4B, if circulation of drilling mud isstopped, there are no frictional losses and the effective fluid pressuregradient immediately changes to the value given by the hydrostaticpressure 305 reflecting the density of the drilling fluid. There maybethe risk of losing control of the well if the hydrostatic pressure isnot then somewhat above the pore pressure in order to avoid an inrush offormation fluids into the borehole. Pressure gradient line 311represents the fluid pressure in the drilling string.

[0038]FIG. 4C illustrates the effect of having a controlled liftingdevice (i.e., pump 30 or injector 62) at a depth 340. The depth 340could be at the sea floor or lower in the wellbore itself. The pressureprofile 309 corresponds to the same mud weight and friction loss as 309in FIG. 4B. At the depth corresponding to 340, a controlled liftingdevice is used to reduce the annular pressure from 346 to 349. Thewellbore and the pressure profile now follow pressure gradient line 347and give a bottom hole pressure of 348, which is below the fracturepressure FP of the formation. Thus, by use of the present invention, itis possible to drill down to and beyond the depth 307 using conventionaldrilling mud, whereas with prior art techniques shown in FIG. 4C itwould not have been possible to do so even with a drilling fluid ofreduced density.

[0039] There are a number of advantages of this invention that areevident. As noted above, it is possible to use heavier mud, typicallywith densities of 8 to 18 lbs. per gallon for drilling: the heavierweight mud provides lubrication and is also better able to bring upcuttings to the surface. The present invention makes it possible todrill to greater depths using heavier weight mud. Prior art techniquesthat relied on changing the mud weight by addition of light-weightcomponents take several hours to adjust the bottom hole pressure,whereas the present invention can do so almost instantaneously. Thequick response also makes it easier to control the bottom hole pressurewhen a kick is detected, whereas with prior art techniques, there wouldhave been a dangerous period during which the control of the well couldhave been lost while the mud weight is being adjusted. The ability tofine-tune the bottom hole pressure also means that there is a reducedrisk of formation damage and allow the wellbore to be drilled and casingset in accordance with the wellbore plan.

[0040] While the foregoing disclosure is directed to the preferredembodiments of the invention, various modifications will be apparent tothose skilled in the art. It is intended that all variations within thescope and spirit of the appended claims be embraced by the foregoingdisclosure.

What is claimed is:
 1. A method of performing downhole subsea wellboreoperations utilizing a wellbore system having a tubing, a bottom holeassembly carried on the tubing adjacent the lower end thereof, a subseawellhead assembly at the top of the wellbore receiving the tubing andbottom hole assembly, and a fluid return line extending from thewellhead assembly to the sea level, the method of drilling comprising:(a) positioning the bottom hole assembly in the wellbore below thewellhead assembly; (b) pumping a fluid down the tubing to the bottomhole assembly; (c) flowing wellbore return fluid through an annulusbetween the tubing and the wellbore to the wellhead and up the returnline from the wellhead to the sea level, with the tubing, annulus,wellhead assembly and return line constituting a subsea fluidcirculation system; (d) providing an adjustable pump system in fluidflow communication with said annulus; and (e) regulating the fluidpressure at the bottom of the borehole at predetermined values duringdownhole operations in the wellbore by operating the adjustable pumpsystem to overcome at least a portion of the hydrostatic pressure andfriction loss pressure of the return fluid.
 2. The method of claim 1wherein regulating the fluid pressure in the borehole further comprisesinjecting a lower density flowable material than the return fluid intothe fluid circulation system to assist the operation of the adjustablepump system in overcoming the hydrostatic and friction loss pressures ofthe return fluid.
 3. The method of claim 2 further comprisingcontrolling the flow rate at which the lower density flowable materialis injected into the return fluid.
 4. The method of claim 1 whereinregulating the fluid pressure in the borehole further comprises blockingflow of return fluid or the flow of fluid in the tubing when theadjustable pump system is not in operation.
 5. The method of claim 1further comprising: (a) sensing an operating parameter of the fluidcirculation system indicative of the pressure or flow rate of the fluidin the fluid circulation system; (b) transmitting a signalrepresentative of the sensed parameter; and (c) controlling theadjustable pump system at least in part based on said signal.
 6. Themethod of claim 1 wherein the pressure of the borehole is regulated atpredetermined values below the fracture pressure of the formation. 7.The method of claim 6 wherein the pressure of the borehole is regulatedat predetermined values above the pore pressure of the formation.
 8. Awellbore system for performing subsea downhole wellbore operations at anoffshore location comprising: (a) tubing receiving fluid under pressureadjacent the upper end thereof; (b) a bottom hole assembly adjacent thelower end of the tubing; (c) a subsea wellhead assembly at the top ofthe wellbore receiving the tubing and the bottom hole assembly, saidwellhead assembly adapted to receive said fluid after it has passed downthrough said tubing and back up through an annulus between the tubingand the wellbore; (d) a fluid return line extending up from the wellheadassembly to the sea level for conveying return fluid from the wellheadto the sea level, with the tubing, annulus, wellhead and return lineconstituting a subsea fluid circulation system; and (e) an adjustablepump system in fluid communication with said annulus for regulating thebottom hole pressure at predetermined values during downhole operationsin the wellbore to overcome at least a portion of the hydrostaticpressure and friction loss pressures of the return fluid.
 9. Thewellbore system of claim 8 further comprising: (a) a source of flowablematerial having density lower than the density of the return fluid; and(b) an injector for injecting said flowable material into the returnfluid during downhole operations in the wellbore to assist theadjustable pump system in pumping the return fluid.
 10. The wellboresystem of claim 8 wherein said tubing is coiled tubing or jointedtubing.
 11. The wellbore system of claim 8 further comprising a flowcontrol devices in the subsea fluid circulation system, one device inthe tubing or in communication with the return fluid to block flow offluid in the subsea fluid circulation system when the adjustable pumpsystem is not in operation.
 12. The wellbore system of claim 11 whereinsaid one flow control device in the tubing is a remotely actuated chokefor maintaining positive pressure of the fluid at the surface.
 13. Thewellbore system of claim 12 further comprising a transmitter at thesurface for sending an actuation signal to the choke, a receiverdownhole for receiving the signal and an actuator associated with thereceiver for adjusting the choke.
 14. The wellbore system of claim 8wherein the adjustable pump system comprises a centrifugal pump.
 15. Thewellbore system of claim 8 wherein the adjustable pump system comprisesa pump and a fluid by-pass line for maintaining the flow rate of fluidthrough the pump system generally constant with changes in the speed ofoperation of the pump.
 16. The wellbore system of claim 8 furthercomprising: (a) at least one sensor for sensing an operating parameterof the subsea fluid circulation system indicative of the pressure orflow rate of fluid in the fluid circulation system; (b) a transmitterfor transmitting a signal representative of the sensed parameter; and(c) a controller for controlling the operation of the adjustable pumpbased at least in part on said signal.
 17. The wellbore system of claim9 wherein the injector is adjustable to control the flow rate at whichthe lower density material is injected into the return fluid.
 18. Thewellbore system of claim 8 wherein the return fluid flow is in a risersurrounding the tubing or in a return line separate and spaced apartfrom the tubing.
 19. A method of drilling a subsea wellbore utilizing adrilling system having tubing, a bottom hole assembly carried adjacentthe lower end of the tubing, a subsea wellhead assembly at the top ofthe wellbore receiving the tubing and bottom hole assembly, and a fluidreturn line separate and spaced apart from the tubing extending from thewellhead assembly to the sea level, with the tubing, annulus, wellheadassembly and return line constituting a circulation system, the methodof drilling comprising: (a) positioning the bottom hole assembly in thewellbore below the wellhead assembly; (b) pumping drilling fluid downthe tubing to the bottom hole assembly; (c) flowing wellbore returnfluid through an annulus between the tubing and the wellbore to thewellhead and up the return line from the wellhead to the sea level; and(d) regulating the fluid pressure in the borehole at predeterminedvalues during downhole operations in the wellbore by injecting flowablematerial of a lower density than the return fluid to overcome at least aportion of the hydrostatic pressure and friction loss pressure of thereturn fluid.
 20. The method of claim 19 wherein regulating the fluidpressure in the borehole further comprises blocking flow of the returnfluid in the circulation system or the flow of the drilling fluid in thetubing when the lower density flowable material is not being injected.21. The method of claim 19 further comprising: (a) sensing an operatingparameter of the fluid circulation system indicative of pressure or flowrate of the fluid in the circulation system; (b) transmitting a signalrepresentative of the sensed parameter; and (c) controlling theinjection of lower density material at least in part based on saidsignal.
 22. The method of claim 17 wherein regulating the fluid pressurein the borehole further comprises operating an adjustable pump system toassist the injection of lower density flowable material in overcomingthe hydrostatic and friction loss pressures.
 23. The method of claim 19wherein the pressure of the borehole is regulated at predeterminedvalues below the fracture pressure of the formation.
 24. The method ofclaim 23 wherein the pressure of the borehole is regulated atpredetermined values above the pore pressure of the formation.
 25. Themethod of claim 19 wherein the tubing is coiled tubing or jointedtubing.
 26. A drilling system for drilling a wellbore at an offshorelocation comprising: (a) tubing receiving drilling fluid under pressureadjacent the upper end thereof, (b) a bottom hole assembly adjacent thelower end of the tubing; (c) a subsea wellhead assembly at the top ofthe wellbore receiving the tubing and the bottom hole assembly, saidwellhead assembly adapted to receive said fluid after it has passedthrough said tubing and through the annulus between the tubing and thewellbore; (d) a fluid return line separate and spaced apart from thetubing extending up from the wellhead assembly to the sea level forconveying said fluid from the wellhead to the sea level, with thetubing, annulus, wellhead and return line constituting a fluidcirculation system; (e) a source of flowable material having a densitylower than the density of the return fluid; and (f) an injector in fluidcommunication with the fluid circulation system for injecting saidflowable material into the return fluid to maintain the bottom holepressure at predetermined values during downhole operations in thewellbore to overcome at least a portion of the hydrostatic pressure andfriction loss pressures in the return fluid.
 27. The drilling system ofclaim 26 further comprising: (a) at least one sensor for sensing anoperating parameter of the fluid circulation system indicative of thepressure or flow rate of the fluid in the fluid circulation system; (b)a transmitter for transmitting a signal representative of the sensedparameter; and (c) a controller for controlling the operation of theinjector based at least in part on said signal.
 28. The drilling systemof claim 26 further comprising at least one flow control device in thefluid circulation system to control the flow of the fluid in the fluidcirculation system.
 29. The drilling system of claim 26 furthercomprising at least two flow control devices in the fluid circulationsystem, one device in the tubing and the other in the fluidcommunication with the return fluid to block flow of fluid when theinjector is not in operation.
 30. The drilling system of claim 29wherein said flow control device in the tubing is a remotely actuatedchoke for maintaining positive pressure of the drilling fluid at thesurface.
 31. The drilling system of claim 30 further comprising atransmitter at the surface for sending an actuation signal to the choke,a receiver downhole for receiving the signal and an actuator associatedwith the receiver for adjusting the choke.
 32. The drilling system ofclaim 26 wherein the injector is adjustable to control the flow rate atwhich the lower density material is injected into the return fluid. 33.The drilling system of claim 26 wherein said tubing is coiled tubing orjointed tubing.
 34. A wellbore system for performing downhole subseaoperations in a wellbore at an offshore location, comprising: (a) tubingreceiving fluid under pressure adjacent the upper end thereof; (b) abottom hole assembly adjacent the lower end of the tubing; (c) a subseawellhead assembly at the top of the wellbore receiving the tubing andthe bottom hole assembly, said wellhead assembly adapted to receive saidfluid after it has passed down through said tubing and back up throughthe annulus between the tubing and the wellbore; (d) a fluid return lineseparate and spaced apart from the tubing extending up from the wellheadassembly to the sea level for conveying return fluid from the wellheadto the sea level, with the tubing, annulus, wellhead and return lineconstituting a subsea fluid circulation system; (e) an adjustable fluidlift in fluid communication with the subsea fluid circulation system forregulating the fluid pressure at predetermined values during downholeoperations in the wellbore by overcoming at least a portion of thehydrostatic pressure and friction loss pressures of the return fluid;and (f) a fluid surge vessel extending up from adjacent the wellhead tothe surface and in fluid communication with return fluid from theannulus, said vessel holding a lower column of return fluid and an uppercolumn of water with the height of the column of return fluid indicativeof the differential pressure of the return fluid and the sea wateradjacent the wellhead.
 35. The wellbore system of claim 34 furthercomprising a valve adjacent the wellhead to block fluid communicationbetween return fluid from the annulus and the fluid surge vessel. 36.The wellbore system of claim 34 wherein the fluid surge vessel is astand pipe.
 37. The wellbore system of claim 34 wherein the tubereceives the tubing and serves as a guide for the tubing.
 38. Thewellbore system of claim 34 further comprising a sensor for measuring aparameter indicative of the volume of water flowing into and out of thevessel, with changes in the pressure of the return fluid adjacent thewellhead.